1. Field of the Invention
The present invention relates to rotary drill bits and their operation and, more specifically, to the design of such rotary drill bits for optimum performance in the context of controlling or maintaining stability (e.g., reducing vibration) during use.
2. Background of Related Art
Rotary drill bits employing cutting elements such as polycrystalline diamond compact (PDC) cutters have been employed for several decades. PDC cutters are typically comprised of a disc-shaped diamond table formed on and bonded (under ultra-high pressure, ultra-high temperature conditions) to a supporting substrate such as a substrate comprising cemented tungsten carbide (WC), although other configurations are known in the art. Rotary drill bits carrying PDC cutters, also known as so-called “fixed cutter” drag bits, have proven very effective in achieving high rates of penetration (ROP) in drilling subterranean formations exhibiting low to medium compressive strengths. Improvements in stability of rotary drill bits, based on cutting element design, cutting element placement, and cutting element force analysis, have reduced prior, notable tendencies of such bits to vibrate in a deleterious manner, also known as “whirling.”
For instance, so-called “anti-whirl” drilling structures are disclosed in U.S. Pat. No. 5,402,856 to Warren, et al., asserting that a bearing surface aligned with a resultant radial force generated by an anti-whirl under-reamer should be sized so that force per area applied to the borehole sidewall will not exceed the compressive strength of the formation being under-reamed. See also U.S. Pat. Nos. 4,982,802 to Warren et al., 5,010,789 to Brett et al., 5,042,596 to Brett et al., 5,111,892 to Sinor et al. and 5,131,478 to Brett et al.
Even in view of such improvements, however, cutting elements, particularly PDC cutters, may still suffer generally from overloading due to a relatively large depth of cut or rotary drill bit instability. For example, drilling into low compressive strength subterranean formations may allow an unduly great depth of cut (DOC) to be achieved at extremely low weight-on-bit (WOB). Further, cutting element damage may occur if a harder subterranean formation is encountered or hard pockets or structures known as “stringers” are suddenly encountered by the rotary drill bit traveling at an unduly great DOC. The problem may also be aggravated by so-called “string bounce,” wherein the elasticity of the drill string may cause erratic application of WOB to the drill bit, with consequent overloading. Moreover, operating PDC cutters at an excessively high DOC may generate more formation cuttings than can be consistently cleared from the bit face and through the junk slots, leading to bit balling, as known in the art.
Another, separate problem involves drilling from a zone or stratum of higher formation compressive strength to a zone of lower strength. As the bit drills into the softer formation without changing the applied WOB (or before the WOB can be changed by the directional driller), the penetration of the PDC cutters, and thus the resulting torque on the bit, increase almost instantaneously and by a substantial magnitude. The abruptly higher torque, in turn, may cause damage to the cutters. In directional drilling, such a change may cause the tool face orientation of the directional (measuring while drilling, or MWD, or a steering tool) assembly to fluctuate, making it more difficult for a directional driller to follow a planned directional path for the bit and necessitating resetting the tool face. In addition, a downhole motor, such as the drilling fluid-driven Moineau motors commonly employed in directional drilling operations in combination with a steerable bottomhole assembly, may completely stall under a sudden torque increase, stopping the drilling operation and again necessitating reestablishing drilling fluid flow and motor output.
Numerous attempts utilizing varying approaches have been made over the years to protect the integrity of a cutting element such as a PDC cutter and its mounting structure, and to limit cutting element penetration into a formation being drilled. For example, from a period even before the advent of commercial use of PDC cutters, U.S. Pat. No. 3,709,308 to Rowley et al., discloses the use of trailing, round natural diamonds on the bit body to limit the penetration of cubic diamonds employed to cut a formation. U.S. Pat. No. 4,351,401 to Fielder discloses the use of surface set natural diamonds at or near the gage of the bit as penetration limiters to control the depth of cut of PDC cutters on the bit face. Other patents disclose the use of a variety of structures immediately trailing PDC cutters (with respect to the direction of bit rotation) to protect the cutters or their mounting structures: U.S. Pat. Nos. 4,889,017 to Fuller et al., 4,991,670 to Fuller et al., 5,244,039 to Newton, Jr., et al., and 5,303,785 to Duke. In addition, U.S. Pat. No. 5,314,033 to Tibbitts, assigned to the assignee of the present invention, discloses, inter alia, the use of cooperating positive and negative or neutral back rake cutters to limit penetration of the positive rake cutters into the formation. Another approach to limiting cutting element penetration is to employ structures or features on the bit body rotationally preceding (rather than trailing) PDC cutters, as disclosed in U.S. Pat. Nos. 3,153,458 to Short, 4,554,986 to Jones, 5,199,511 to Tibbitts et al., and 5,595,252 to O'Hanlon.
U.S. Pat. No. 6,298,930 to Sinor et al. and U.S. Pat. No. 6,460,631 to Dykstra et al., assigned to the assignee of the present invention and the disclosures of each of which are incorporated, in their entireties by reference herein, respectively relate to bit designs including depth of cut control (DOCC) features which may rotationally lead at least some of the PDC cutters on the bit face on which the bit may ride while the PDC cutters of the bit are engaged with the formation to their design DOC. Stated another way, the cutter standoff or exposure may be substantially controlled by the DOCC features, and such control may enable a relatively greater DOC (and thus ROP for a given bit rotational speed) than with a conventional bit design. Particularly, the DOCC features may preclude a greater DOC than that designed for by distributing the load attributable to WOB over a sufficient surface area on the bit face, blades or other bit body structure contacting the uncut formation face at the borehole bottom so that the compressive strength of the formation will not be exceeded by the DOCC features. As a result, the bit does not substantially indent, or fail, the formation rock and permits greater than intended cutter penetration and consequent increase in cutter loading and torque.
U.S. Pat. No. 6,659,199 to Swadi, assigned to the assignee of the present invention and the disclosure of which is incorporated in its entirety by reference herein, relates to a rotary drag bit carrying PDC cutters and elongated bearing elements associated with at least some of the PDC cutters on the bit face thereof. Lateral positioning and angular positioning of the elongated bearing elements are adjusted so that all portions of an elongated bearing element travel substantially completely within a tubular clearance volume defined by the path through the formation being drilled by a PDC cutter with which that elongated bearing element is associated, the associated PDC cutter being positioned at about the same radius from the bit centerline as the elongated bearing element.
While some of the foregoing patents recognize the desirability to limit cutter penetration or DOC, other patents emphasize stability approaches for limiting forces applied to cutting elements carried by a rotary drill bit, the disclosed approaches are somewhat isolated in nature and fail to accommodate or implement an engineered approach to achieving both improved stability and limiting the penetration rate or DOC.